ENERGY PARTNERS LTD - 10-K Annual Report

Back to GetFilings.com

- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

COMMISSION FILE NUMBER: 001-16179
---------------------
ENERGY PARTNERS, LTD.
(Exact name of registrant as specified in its charter)

DELAWARE 72-1409562
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

201 ST. CHARLES AVENUE, SUITE 3400 70170
NEW ORLEANS, LOUISIANA (Zip Code)
(Address of principal executive offices)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
504-569-1875

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
NONE
---------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Act). Yes [X] No [ ]

The aggregate market value of the common stock held by non-affiliates of
the registrant at June 30, 2004 based on the closing price of such stock as
quoted on the New York Stock Exchange on that date was $411,966,974.

As of February 25, 2005 there were 35,884,066 shares of the registrant's
common stock, par value $0.01 per share, outstanding.

Documents incorporated by reference: Portions of the registrant's
definitive proxy statement for its 2005 Annual Meeting of Stockholders have been
incorporated by reference into Part III of this Form 10-K.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

TABLE OF CONTENTS

2

FORWARD LOOKING STATEMENTS

All statements other than statements of historical fact contained in this
Report on Form 10-K ("Report") and other periodic reports filed by us under the
Securities Exchange Act of 1934 and other written or oral statements made by us
or on our behalf, are forward-looking statements. When used herein, the words
"anticipates", "expects", "believes", "goals", "intends", "plans", or "projects"
and similar expressions are intended to identify forward-looking statements. It
is important to note that forward-looking statements are based on a number of
assumptions about future events and are subject to various risks, uncertainties
and other factors that may cause our actual results to differ materially from
the views, beliefs and estimates expressed or implied in such forward-looking
statements. We refer you specifically to the section "Additional Factors
Affecting Business" in Items 1 and 2 of this Report. Although we believe that
the assumptions on which any forward-looking statements in this Report and other
periodic reports filed by us are reasonable, no assurance can be given that such
assumptions will prove correct. All forward-looking statements in this Report
are expressly qualified in their entirety by the cautionary statements in this
paragraph and elsewhere in this Report.

PART I

ITEMS 1 & 2. BUSINESS AND PROPERTIES

We are an independent oil and natural gas exploration and production
company. Since our inception in 1998 we have focused on the shallow to moderate
depth waters of the Gulf of Mexico Shelf. With the acquisition of south
Louisiana properties in January 2005, discussed below, we have expanded our
focus area to include the onshore Gulf Coast, which is similar geologically to
the Gulf of Mexico Shelf. We concentrate on this region because that area
provides us with favorable geologic and economic conditions, including multiple
reservoir formations, regional economies of scale, extensive infrastructure and
comprehensive geologic databases. We believe that this region offers a balanced
and expansive array of existing and prospective exploration, exploitation and
development opportunities in both established productive horizons and deeper
geologic formations. As of December 31, 2004, we had estimated proved reserves
of approximately 149.8 Bcf of natural gas and 28.8 Mmbbls of oil, or an
aggregate of approximately 53.7 Mmboe, with a present value of estimated pre-tax
future net cash flows of $924.1 million, and a standardized measure of
discounted future net cash flows of $667.7 million.

Since our incorporation in January 1998 by Richard A. Bachmann, chairman,
president and chief executive officer, we have assembled a team of geoscientists
and management professionals with considerable region-specific geological,
geophysical, technical and operational experience. We have grown through a
combination of exploration, exploitation and development drilling and
multi-year, multi-well drill-to-earn programs, as well as strategic acquisitions
of mature oil and natural gas fields in the Gulf of Mexico Shelf area, including
the acquisition of Hall-Houston Oil Company ("HHOC") in early 2002. As we have
grown, we have strengthened our management team, expanded our property base,
reduced our geographic concentration, and moved to a more balanced oil and
natural gas reserves and production profile. We have also expanded our technical
knowledge base through the addition of high quality personnel and geophysical
and geological data.

On November 1, 2000, we consummated our initial public offering and began
trading our common shares on the New York Stock Exchange under the symbol "EPL."
We maintain a website at www.eplweb.com which contains information about us,
including links to our annual report on Form 10-K, quarterly reports on Form
10-Q, current reports on Form 8-K and all related amendments. In addition, our
website contains our Corporate Governance Guidelines and the charters for our
Audit, Compensation and Nominating Committees. Copies of such information are
also available by writing to The Secretary of the Company at 201 St. Charles
Avenue, Suite 3400, New Orleans, Louisiana 70170. Our web site and the
information contained in it and connected to it shall not be deemed incorporated
by reference into this Report on Form 10-K.

3

ACQUISITION OF SOUTH LOUISIANA RESERVES AND PROSPECTS

On January 20, 2005, we closed the acquisition of properties and reserves
onshore in south Louisiana from Castex Energy 1995, L.P. and Castex Energy, Inc.
("Castex") for $146.0 million in cash, after adjustments for the exercise of
preferential rights by third parties and preliminary closing adjustments. The
properties acquired include nine fields, four of which were producing at the
time of the closing through 14 wells, with estimated proved reserves of 51.2
Bcfe. Also included were interests in 22 exploratory prospects scheduled to be
drilled in 2005. Concurrent with the closing, our bank credit facility borrowing
base was increased to $150 million, of which $60 million was drawn to fund the
acquisition.

This acquisition has taken us into onshore south Louisiana, where our staff
has a wealth of experience. In connection with the acquisition, we also entered
into a two-year agreement with the seller of the properties that defines an area
of mutual interest ("AMI") encompassing over one million acres in which we
intend to jointly explore and develop oil and gas reserves over the next two
years. Both the proved reserves acquired from the seller and the AMI are in the
southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.

EXPLORATION AND DEVELOPMENT EXPENDITURES

Our exploration and development expenditures for 2004 totaled $194.2
million inclusive of a $2.2 million contingent consideration payment to former
HHOC stockholders resulting from the January 2002 acquisition of HHOC. For 2005,
we have budgeted exploration and development expenditures of $240 million. This
budget includes exploration and development activities on the newly acquired
properties in south Louisiana as well as exploration and development activities
on our offshore properties. The drilling portfolio, both onshore and offshore,
includes a mixture of lower risk development and exploitation wells, moderate
risk exploration opportunities and higher risk, higher potential exploration
projects. Our 2005 budget does not include any acquisitions of proved reserves
that may occur during the year, including the acquisitions of properties and
reserves to date in 2005.

OUR PROPERTIES

At December 31, 2004, we had interests in 29 producing fields, 5 fields
under development and one field on which drilling operations were then being
conducted, all of which are located in the Gulf of Mexico Shelf region. These
fields fall into three focus areas which we identify as our Eastern, Central and
Western areas. The Eastern area is comprised of two fields, including the East
Bay field. The Central area is comprised of six fields, four of which are
contiguous and together cover most of the Bay Marchand salt dome. The Western
area which extends from areas offshore central and western Louisiana to areas
offshore Texas, is comprised of 21 producing fields. Over the last several
years, we have continued to add to our leasehold acreage position in these areas
through federal and state lease sales and trades with industry partners.

EASTERN AREA

East Bay is the key asset in our Eastern area and is located 89 miles
southeast of New Orleans near the mouth of the Mississippi River. East Bay
contains producing wells located onshore along the coastline and in water depths
ranging up to approximately 171 feet. East Bay encompasses nearly 48 square
miles and is comprised primarily of the South Pass 24, 26 and 27 fields. Through
recent state and federal lease sales, we acquired acreage that is contiguous to
East Bay in several additional South Pass and West Delta blocks. We are the
operator of all of these fields and own an average 96% interest in our acreage
position with our working interest ranging from 18% to 100% and our net revenue
interest varying up to a maximum of 86%. Inclusive of all lease acquisitions,
our leasehold area covers 47,402 gross acres (45,499 net acres).

Our Eastern area operations accounted for approximately 33% of our net
daily production and 15% ($28.2 million) of our capital expenditures during
2004.

4

CENTRAL AREA

Our Central area is located approximately 60 miles south of New Orleans in
water depths of 168 feet or less and encompasses nearly 100 square miles. The
focus of our central area operations is the Greater Bay Marchand area. Our key
assets in this area include the South Timbalier 26 and 41 and Bay Marchand
fields as well as currently undeveloped reserves in the South Timbalier 46
field.

In 2003, we drilled our initial discovery well in South Timbalier 41 on
acreage acquired earlier that year in a federal lease sale. Three follow up
wells have been drilled in the field, two of which were brought on production in
early 2005. Development is currently under way for the third well and a fourth
exploratory well is planned for early 2005. This field, in which additional
reserve potential is yet to be tested, represents the most significant discovery
in our history. In addition, through a series of transactions culminating in
early 2000, as of December 31, 2004 we owned a 50% interest in the South
Timbalier 26 field. We serve as operator of this field where we have interests
in 12 producing wells.

On March 8, 2005, we closed the acquisition of the remaining 50% gross
working interest in South Timbalier 26, above approximately 13,000 feet subsea
that we did not already own from Apache Corporation for approximately $21.0
million after preliminary closing adjustments from the effective date of
December 1, 2004. As a result of the acquisition, we now own a 100% gross
working interest in this field. The acquisition expands our interest in our core
Greater Bay Marchand area and gives us additional flexibility in undertaking the
future development of the South Timbalier 26 field.

Our Central area operations accounted for approximately 27% of our net
daily production and 32% ($61.5 million) of capital expenditures during 2004.

WESTERN AREA

The properties in the Western area are located in water depths ranging from
20 to 476 feet with working interests ranging from 17% to 100%. We owned
interests in 27 fields in this area at December 31, 2004, 21 of which were
producing fields with another five under development and one on which drilling
was then in progress.

Our Western area operations accounted for approximately 40% of our net
daily production and 53% ($104.5 million) of our capital expenditures during
2004.

5

OIL AND NATURAL GAS RESERVES

The following table presents our estimated net proved oil and natural gas
reserves and the present value of our reserves at December 31, 2004, 2003 and
2002. The December 31, 2004, 2003 and 2002 estimates of proved reserves are
based on reserve reports prepared by Netherland, Sewell & Associates, Inc. and
Ryder Scott Company, L.P., independent petroleum engineers. Neither the present
values, discounted at 10% per annum, of estimated future net cash flows before
income taxes, or the standardized measure of discounted future net cash flows
shown in the table are intended to represent the current market value of the
estimated oil and natural gas reserves we own.

- ---------------

(1) Approximately 69% of our total proved reserves were proved undeveloped and
proved developed non-producing at December 31, 2004.

(2) Net proved developed non-producing reserves as of December 31, 2004 were
12,976 Mbbls and 72,073 Mmcf.

(3) The December 31, 2004 amount was calculated using a period-end oil price of
$41.84 per barrel and a period-end natural gas price of $6.23 per Mcf, while
the December 31, 2003 amount was calculated using a period-end oil price of
$30.88 per barrel and a period-end natural gas price of $6.15 per Mcf and
the December 31, 2002 amount was calculated using a period-end oil price of
$29.53 per barrel and a period-end price of $4.83 per Mcf.

(4) The present value of estimated future net revenues attributable to our
reserves was prepared using constant prices, as of the calculation date,
discounted at 10% per year on a pre-tax basis.

(5) The standardized measure of discounted future net cash flows represents the
present value of future cash flows after income tax discounted at 10%.

6

COSTS INCURRED IN OIL AND NATURAL GAS ACTIVITIES

The following table sets forth certain information regarding the costs
incurred that are associated with finding, acquiring, and developing our proved
oil and natural gas reserves:

PRODUCTIVE WELLS

The following table sets forth the number of productive oil and natural gas
wells in which we owned an interest as of December 31, 2004:

Productive wells consist of producing wells and wells capable of
production, including oil wells awaiting connection to production facilities and
natural gas wells awaiting pipeline connections to commence deliveries. Three
gross oil wells and five gross natural gas wells have dual completions.

7

ACREAGE

The following table sets forth information as of December 31, 2004 relating
to acreage held by us. Developed acreage is assigned to producing wells.

Leases covering 8% of our undeveloped net acreage will expire in 2005,
approximately 28% in 2006, 15% in 2007, 11% in 2008, and 38% in 2009.

WELL ACTIVITY

The following table shows our well activity for the years ended December
31, 2004, 2003 and 2002. In the table, "gross" refers to the total wells in
which we have a working interest and "net" refers to gross wells multiplied by
our working interest in these wells.

Well activity refers to the number of wells completed at any time during
the fiscal years, regardless of when drilling was initiated. For the purpose of
this table, "completed" refers to the installation of permanent equipment for
the production of oil or natural gas.

TITLE TO PROPERTIES

Our properties are subject to customary royalty interests, liens under
indebtedness, liens incident to operating agreements, mechanics and materialman
liens for current taxes and other burdens, including other mineral encumbrances
and restrictions. We do not believe that any of these burdens materially
interfere with the use of our properties in the operation of our business.

We believe that we have satisfactory title to, or rights in, all of our
producing properties. As is customary in the oil and natural gas industry,
minimal investigation of title is made at the time of acquisition of
8

undeveloped properties. We investigate title prior to the consummation of an
acquisition of producing properties and before the commencement of drilling
operations on undeveloped properties. We have obtained or conducted a thorough
title review on substantially all of our producing properties and believe that
we have satisfactory title to such properties in accordance with standards
generally accepted in the oil and natural gas industry.

REGULATORY MATTERS

REGULATION OF TRANSPORTATION AND SALE OF NATURAL GAS

Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938,
as amended ("NGA"), the Natural Gas Policy Act of 1978, as amended ("NGPA"), and
regulations promulgated thereunder by the Federal Energy Regulatory Commission
("FERC") and its predecessors. In the past, the federal government has regulated
the prices at which natural gas could be sold. While sales by producers of
natural gas can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future. Deregulation of wellhead natural gas sales
began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas
Wellhead Decontrol Act, as amended (the "Decontrol Act"). The Decontrol Act
removed all NGA and NGPA price and non-price controls affecting wellhead sales
of natural gas effective January 1, 1993.

Since 1985, FERC has endeavored to make natural gas transportation more
accessible to natural gas buyers and sellers on an open and non-discriminatory
basis. FERC has stated that open access policies are necessary to improve the
competitive structure of the interstate natural gas pipeline industry and to
create a regulatory framework that will put natural gas sellers into more direct
contractual relations with natural gas buyers by, among other things, unbundling
the sale of natural gas from the sale of transportation and storage services.
Beginning in 1992, FERC issued Order No. 636 and a series of related orders
(collectively, "Order No. 636") to implement its open access policies. As a
result of the Order No. 636 program, the marketing and pricing of natural gas
have been significantly altered. The interstate pipelines' traditional role as
wholesalers of natural gas has been eliminated and replaced by a structure under
which pipelines provide transportation and storage service on an open access
basis to others who buy and sell natural gas. Although FERC's orders do not
directly regulate natural gas producers, they are intended to foster increased
competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders (collectively,
"Order No. 637"), which imposed a number of additional reforms designed to
enhance competition in natural gas markets. Among other things, Order No. 637
revised FERC pricing policy by waiving price ceilings for short-term released
capacity for a two-year experimental period, and effected changes in FERC
regulations relating to scheduling procedures, capacity segmentation, penalties,
rights of first refusal and information reporting. Most major aspects of Order
No. 637 have been upheld on judicial review, and most pipelines' tariff filings
to implement the requirements of Order No. 637 have been accepted by the FERC
and placed into effect.

The Outer Continental Shelf Lands Act ("OCSLA"), which FERC implements as
to transportation and pipeline issues, requires that all pipelines operating on
or across the outer continental shelf ("OCS") provide open access,
non-discriminatory transportation service. One of FERC's principal goals in
carrying out OCSLA's mandate is to increase transparency in the market to
provide producers and shippers on the OCS with greater assurance of open access
service on pipelines located on the OCS and non-discriminatory rates and
conditions of service on such pipelines.

It should be noted that FERC currently is considering whether to
reformulate its test for defining non-jurisdictional gathering in the shallow
waters of the OCS and, if so, what form that new test should take. The stated
purpose of this initiative is to devise an objective test that furthers the
goals of the NGA by protecting producers from the unregulated market power of
third-party transporters of gas, while providing incentives for investment in
production, gathering and transportation infrastructure offshore. While we
cannot predict whether FERC's gathering test ultimately will be revised and, if
so, what form such revised test will take, any test that refunctionalizes as
FERC-jurisdictional transmission facilities currently classified as gathering
would

9

impose an increased regulatory burden on the owner of those facilities by
subjecting the facilities to NGA certificate and abandonment requirements and
rate regulation.

We cannot accurately predict whether FERC's actions will achieve the goal
of increasing competition in markets in which our natural gas is sold.
Additional proposals and proceedings that might affect the natural gas industry
are pending before FERC and the courts. The natural gas industry historically
has been very heavily regulated; therefore, there is no assurance that the less
stringent regulatory approach recently pursued by FERC will continue. However,
we do not believe that any action taken will affect us in a way that materially
differs from the way it affects other natural gas producers, gatherers and
marketers.

Intrastate natural gas transportation is subject to regulation by state
regulatory agencies. The basis for intrastate regulation of natural gas
transportation and the degree of regulatory oversight and scrutiny given to
intrastate natural gas pipeline rates and services varies from state to state.
Insofar as such regulation within a particular state will generally affect all
intrastate natural gas shippers within the state on a comparable basis, we
believe that the regulation of similarly situated intrastate natural gas
transportation in any states in which we operate and ship natural gas on an
intrastate basis will not affect our operations in any way that is materially
different from the effect of such regulation on our competitors.

REGULATION OF TRANSPORTATION OF OIL

Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at negotiated prices. The transportation of oil in common
carrier pipelines is also subject to rate regulation. FERC regulates interstate
oil pipeline transportation rates under the Interstate Commerce Act. In general,
interstate oil pipeline rates must be cost-based, although settlement rates
agreed to by all shippers are permitted and market-based rates may be permitted
in certain circumstances. Effective January 1, 1995, FERC implemented
regulations establishing an indexing system (based on inflation) for
transportation rates for oil that allowed for an increase or decrease in the
cost of transporting oil to the purchaser. A review of these regulations by the
FERC in 2000 was successfully challenged on appeal by an association of oil
pipelines. On remand, the FERC in February 2003 increased the index slightly,
effective July 2001. Intrastate oil pipeline transportation rates are subject to
regulation by state regulatory commissions. The basis for intrastate oil
pipeline regulation, and the degree of regulatory oversight and scrutiny given
to intrastate oil pipeline rates, varies from state to state. Insofar as
effective interstate and intrastate rates are equally applicable to all
comparable shippers, we believe that the regulation of oil transportation rates
will not affect our operations in any way that is materially different from the
effect of such regulation on our competitors.

Further, interstate and intrastate common carrier oil pipelines must
provide service on a non-discriminatory basis. Under this open access standard,
common carriers must offer service to all shippers requesting service on the
same terms and under the same rates. When oil pipelines operate at full
capacity, access is governed by prorationing provisions set forth in the
pipelines' published tariffs. Accordingly, we believe that access to oil
pipeline transportation services generally will be available to us to the same
extent as to our competitors.

Our subsidiary, EPL Pipeline, L.L.C., owns an approximately 12-mile oil
pipeline, which transports oil produced from South Timbalier 26 and a portion of
South Timbalier 41 on the Gulf of Mexico OCS to Bayou Fourchon, Louisiana.
Production transported on this pipeline includes oil produced by us and our
working interest partner in South Timbalier 26. EPL Pipeline, L.L.C. has on file
with the Louisiana Public Service Commission and FERC tariffs for this
transportation service and offers non-discriminatory transportation for any
willing shipper.

REGULATION OF PRODUCTION

The production of oil and natural gas is subject to regulation under a wide
range of local, state and federal statutes, rules, orders and regulations.
Federal, state and local statutes and regulations require permits for drilling
operations, drilling bonds and plugging and abandonment and reports concerning
operations. The states in which we own and operate properties have regulations
governing conservation matters, including provisions for the unitization or
pooling of oil and natural gas properties, the establishment of maximum
10

allowable rates of production from oil and natural gas wells, the regulation of
well spacing, and plugging and abandonment of wells. Many states also restrict
production to the market demand for oil and natural gas, and states have
indicated interest in revising applicable regulations. The effect of these
regulations is to limit the amount of oil and natural gas that we can produce
from our wells and to limit the number of wells or the locations at which we can
drill. Moreover, each state generally imposes a production or severance tax with
respect to the production and sale of oil, natural gas and natural gas liquids
within its jurisdiction.

Some of our offshore operations are conducted on federal leases that are
administered by Minerals Management Service ("MMS") and are required to comply
with the regulations and orders promulgated by MMS under OCSLA. Among other
things, we are required to obtain prior MMS approval for any exploration plans
we pursue and our development and production plans for these leases. MMS
regulations also establish construction requirements for production facilities
located on our federal offshore leases and govern the plugging and abandonment
of wells and the removal of production facilities from these leases. Under
limited circumstances, MMS could require us to suspend or terminate our
operations on a federal lease.

MMS also establishes the basis for royalty payments due under federal oil
and natural gas leases through regulations issued under applicable statutory
authority. State regulatory authorities establish similar standards for royalty
payments due under state oil and natural gas leases. The basis for royalty
payments established by MMS and the state regulatory authorities is generally
applicable to all federal and state oil and natural gas lessees. Accordingly, we
believe that the impact of royalty regulation on our operations should generally
be the same as the impact on our competitors.

The failure to comply with these rules and regulations can result in
substantial penalties. The regulatory burden on the oil and natural gas industry
increases our cost of doing business and, consequently, affects our
profitability. Our competitors in the oil and natural gas industry are subject
to the same regulatory requirements and restrictions that affect our operations.

ENVIRONMENTAL REGULATIONS

General. Various federal, state and local laws and regulations governing
the protection of the environment, such as the Comprehensive Environmental
Response, Compensation and Liability Act of 1980, as amended ("CERCLA"), the
Federal Water Pollution Control Act of 1972, as amended (the "Clean Water Act"),
and the Federal Clean Air Act, as amended (the "Clean Air Act"), affect our
operations and costs. In particular, our exploration, development and production
operations, our activities in connection with storage and transportation of oil
and other hydrocarbons and our use of facilities for treating, processing or
otherwise handling hydrocarbons and related wastes may be subject to regulation
under these and similar state legislation. These laws and regulations:

- restrict the types, quantities and concentration of various substances
that can be released into the environment in connection with drilling and
production activities;

- limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas; and

- impose substantial liabilities for pollution resulting from our
operations.

Failure to comply with these laws and regulations may result in the
assessment of administrative, civil and criminal fines and penalties or the
imposition of injunctive relief. Changes in environmental laws and regulations
occur regularly, and any changes that result in more stringent and costly waste
handling, storage, transport, disposal or cleanup requirements could materially
adversely affect our operations and financial position, as well as those in the
oil and natural gas industry in general. While we believe that we are in
substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements would not
have a material adverse impact on us, there is no assurance that this trend will
continue in the future.

11

As with the industry generally, compliance with existing regulations
increases our overall cost of business. The areas affected include:

- unit production expenses primarily related to the control and limitation
of air emissions and the disposal of produced water;

- capital costs to drill exploration and development wells primarily
related to the management and disposal of drilling fluids and other oil
and natural gas exploration wastes; and

- capital costs to construct, maintain and upgrade equipment and
facilities.

Superfund. CERCLA, also known as "Superfund," imposes liability for
response costs and damages to natural resources, without regard to fault or the
legality of the original act, on some classes of persons that contributed to the
release of a "hazardous substance" into the environment. These persons include
the "owner" or "operator" of a disposal site and entities that disposed or
arranged for the disposal of the hazardous substances found at the site. CERCLA
also authorizes the Environmental Protection Agency ("EPA") and, in some
instances, third parties to act in response to threats to the public health or
the environment and to seek to recover from the responsible classes of persons
the costs they incur. It is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the environment. In the course
of our ordinary operations, we may generate waste that may fall within CERCLA's
definition of a "hazardous substance." We may be jointly and severally liable
under CERCLA or comparable state statutes for all or part of the costs required
to clean up sites at which these wastes have been disposed.

We currently own or lease properties that for many years have been used for
the exploration and production of oil and natural gas. Although we and our
predecessors have used operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have been disposed or
released on, under or from the properties owned or leased by us or on, under or
from other locations where these wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
actions with respect to the treatment and disposal or release of hydrocarbons or
other wastes were not under our control. These properties and wastes disposed on
these properties may be subject to CERCLA and analogous state laws. Under these
laws, we could be required:

- to remove or remediate previously disposed wastes, including wastes
disposed or released by prior owners or operators;

- to clean up contaminated property, including contaminated groundwater; or

- to perform remedial operations to prevent future contamination.

At this time, we do not believe that we are associated with any Superfund
site and we have not been notified of any claim, liability or damages under
CERCLA.

Oil Pollution Act of 1990. The Oil Pollution Act of 1990, as amended (the
"OPA") and regulations thereunder impose liability on "responsible parties" for
damages resulting from oil spills into or upon navigable waters, adjoining
shorelines or in the exclusive economic zone of the United States. Liability
under OPA is strict, and under certain circumstances joint and several, and
potentially unlimited. A "responsible party" includes the owner or operator of
an onshore facility and the lessee or permittee of the area in which an offshore
facility is located. The OPA also requires the lessee or permittee of the
offshore area in which a covered offshore facility is located to establish and
maintain evidence of financial responsibility in the amount of $35.0 million
($10.0 million if the offshore facility is located landward of the seaward
boundary of a state) to cover liabilities related to an oil spill for which such
person is statutorily responsible. The amount of required financial
responsibility may be increased above the minimum amounts to an amount not
exceeding $150.0 million depending on the risk represented by the quantity or
quality of oil that is handled by the facility. We carry insurance coverage to
meet these obligations, which we believe is customary for comparable companies
in our industry. A failure to comply with OPA's requirements or inadequate
cooperation during a spill response action may subject a responsible party to
civil or criminal enforcement actions. We are not

12

aware of any action or event that would subject us to liability under OPA, and
we believe that compliance with OPA's financial responsibility and other
operating requirements will not have a material adverse effect on us.

U.S. Environmental Protection Agency. U.S. Environmental Protection Agency
regulations address the disposal of oil and natural gas operational wastes under
three federal acts more fully discussed in the paragraphs that follow. The
Resource Conservation and Recovery Act of 1976, as amended ("RCRA"), provides a
framework for the safe disposal of discarded materials and the management of
solid and hazardous wastes. The direct disposal of operational wastes into
offshore waters is also limited under the authority of the Clean Water Act. When
injected underground, oil and natural gas wastes are regulated by the
Underground Injection Control program under Safe Drinking Water Act. If wastes
are classified as hazardous, they must be properly transported, using a uniform
hazardous waste manifest, documented, and disposed at an approved hazardous
waste facility. We have coverage under the Region VI National Production
Discharge Elimination System Permit for discharges associated with exploration
and development activities. We take the necessary steps to ensure all offshore
discharges associated with a proposed operation, including produced waters, will
be conducted in accordance with the permit.

Resource Conservation Recovery Act. RCRA, is the principal federal statute
governing the treatment, storage and disposal of hazardous wastes. RCRA imposes
stringent operating requirements, and liability for failure to meet such
requirements, on a person who is either a "generator" or "transporter" of
hazardous waste or an "owner" or "operator" of a hazardous waste treatment,
storage or disposal facility. At present, RCRA includes a statutory exemption
that allows most oil and natural gas exploration and production waste to be
classified as nonhazardous waste. A similar exemption is contained in many of
the state counterparts to RCRA. As a result, we are not required to comply with
a substantial portion of RCRA's requirements because our operations generate
minimal quantities of hazardous wastes. At various times in the past, proposals
have been made to amend RCRA to rescind the exemption that excludes oil and
natural gas exploration and production wastes from regulation as hazardous
waste. Repeal or modification of the exemption by administrative, legislative or
judicial process, or modification of similar exemptions in applicable state
statutes, would increase the volume of hazardous waste we are required to manage
and dispose of and would cause us to incur increased operating expenses.

Clean Water Act. The Clean Water Act imposes restrictions and controls on
the discharge of produced waters and other wastes into navigable waters. Permits
must be obtained to discharge pollutants into state and federal waters and to
conduct construction activities in waters and wetlands. Certain state
regulations and the general permits issued under the Federal National Pollutant
Discharge Elimination System program prohibit the discharge of produced waters
and sand, drilling fluids, drill cuttings and certain other substances related
to the oil and natural gas industry into certain coastal and offshore waters.
Further, the EPA has adopted regulations requiring certain oil and natural gas
exploration and production facilities to obtain permits for storm water
discharges. Costs may be associated with the treatment of wastewater or
developing and implementing storm water pollution prevention plans. The Clean
Water Act and comparable state statutes provide for civil, criminal and
administrative penalties for unauthorized discharges for oil and other
pollutants and impose liability on parties responsible for those discharges for
the costs of cleaning up any environmental damage caused by the release and for
natural resource damages resulting from the release. We believe that our
operations comply in all material respects with the requirements of the Clean
Water Act and state statutes enacted to control water pollution.

Safe Drinking Water Act. Underground injection is the subsurface placement
of fluid through a well, such as the reinjection of brine produced and separated
from oil and natural gas production. The Safe Drinking Water Act of 1974, as
amended establishes a regulatory framework for underground injection, with the
main goal being the protection of usable aquifers. The primary objective of
injection well operating requirements is to ensure the mechanical integrity of
the injection apparatus and to prevent migration of fluids from the injection
zone into underground sources of drinking water. Hazardous-waste injection well
operations are strictly controlled, and certain wastes, absent an exemption,
cannot be injected into underground injection control wells. In Louisiana and
Texas, no underground injection may take place except as authorized by permit or
rule. We currently own and operate various underground injection wells. Failure
to abide by our permits could subject us to civil and/or criminal enforcement.
We believe that we are in compliance in all
13

material respects with the requirements of applicable state underground
injection control programs and our permits.

Marine Protected Areas. Executive Order 13158, issued on May 26, 2000,
directs federal agencies to safeguard existing Marine Protected Areas ("MPAs")
in the United States and establish new MPAs. The order requires federal agencies
to avoid harm to MPAs to the extent permitted by law and to the maximum extent
practicable. It also directs the EPA to propose new regulations under the Clean
Water Act to ensure appropriate levels of protection for the marine environment.
This order has the potential to adversely affect our operations by restricting
areas in which we may carry out future development and exploration projects
and/or causing us to incur increased operating expenses.

Marine Mammal and Endangered Species. Federal Lease Stipulations address
the reduction of potential taking of protected marine species (sea turtles,
marine mammals, Gulf Sturgen and other listed marine species). MMS permit
approvals will be conditioned on collection and removal of debris resulting from
activities related to exploration, development and production of offshore
leases. MMS has issued Notices to Lessees and Operators ("NTL") 2003-G06
advising of requirements for posting of signs in prominent places on all vessels
and structures and of an observing training program.

Consideration of Environmental Issues in Connection with Governmental
Approvals. Our operations frequently require licenses, permits and/or other
governmental approvals. Several federal statutes, including OCSLA, the National
Environmental Policy Act ("NEPA"), and the Coastal Zone Management Act ("CZMA")
require federal agencies to evaluate environmental issues in connection with
granting such approvals and/or taking other major agency actions. OCSLA, for
instance, requires the U.S. Department of Interior ("DOI") to evaluate whether
certain proposed activities would cause serious harm or damage to the marine,
coastal or human environment. Similarly, NEPA requires DOI and other federal
agencies to evaluate major agency actions having the potential to significantly
impact the environment. In the course of such evaluations, an agency would have
to prepare an environmental assessment and, potentially, an environmental impact
statement. CZMA, on the other hand, aids states in developing a coastal
management program to protect the coastal environment from growing demands
associated with various uses, including offshore oil and natural gas
development. In obtaining various approvals from the DOI, we must certify that
we will conduct our activities in a manner consistent with an applicable
program.

Lead-Based Paints. Various pieces of equipment and structures owned by us
have been coated with lead-based paints as was customary in the industry at the
time these pieces of equipment were fabricated and constructed. These paints may
contain lead at a concentration high enough to be considered a regulated
hazardous waste when removed. If we need to remove such paints in connection
with maintenance or other activities and they qualify as a regulated hazardous
waste, this would increase the cost of disposal. High lead levels in the paint
might also require us to institute certain administrative and/or engineering
controls required by the Occupational Safety and Health Act and MMS to ensure
worker safety during paint removal.

Air Pollution Control. The Clean Air Act and state air pollution laws
adopted to fulfill its mandates provide a framework for national, state and
local efforts to protect air quality. Our operations utilize equipment that
emits air pollutants subject to federal and state air pollution control laws.
These laws require utilization of air emissions abatement equipment to achieve
prescribed emissions limitations and ambient air quality standards, as well as
operating permits for existing equipment and construction permits for new and
modified equipment. Air emissions associated with offshore activities are
projected using a matrix and formula supplied by MMS, which has primacy from the
Environmental Protection Agency for regulating such emissions.

Naturally Occurring Radioactive Materials ("NORM"). NORM are materials not
covered by the Atomic Energy Act, whose radioactivity is enhanced by
technological processing such as mineral extraction or processing through
exploration and production conducted by the oil and natural gas industry. NORM
wastes are regulated under the RCRA framework, but primary responsibility for
NORM regulation has been a state function. Standards have been developed for
worker protection; treatment, storage and disposal of NORM waste; management of
waste piles, containers and tanks; and limitations upon the release of NORM
contaminated land for unrestricted use. We believe that our operations are in
material compliance with all applicable NORM standards established by the State
of Louisiana or the State of Texas, as applicable.
14

Abandonment Costs. One of the responsibilities of owning and operating oil
and natural gas properties is paying for the cost of abandonment. Effective
January 1, 2003, companies are required to reflect estimated abandonment costs
as a liability on their balance sheets in the period in which it is incurred. We
may incur significant abandonment costs in the future which could adversely
affect our financial results. As of December 31, 2004 and 2003, we had $45.1
million and $40.6 million, respectively, reflected in our consolidated balance
sheets for estimated future abandonment.

ADDITIONAL FACTORS AFFECTING BUSINESS

RISKS RELATING TO THE OIL AND NATURAL GAS INDUSTRY

EXPLORING FOR AND PRODUCING OIL AND NATURAL GAS ARE HIGH-RISK ACTIVITIES WITH
MANY UNCERTAINTIES THAT COULD ADVERSELY AFFECT OUR BUSINESS, FINANCIAL
CONDITION OR RESULTS OF OPERATIONS.

Our future success will depend on the success of our exploration and
production activities. Our oil and natural gas exploration and production
activities are subject to numerous risks beyond our control, including the risk
that drilling will not result in commercially viable oil or natural gas
production. Our decisions to purchase, explore, develop or otherwise exploit
prospects or properties will depend in part on the evaluation of data obtained
through geophysical and geological analyses, production data and engineering
studies, the results of which are often inconclusive or subject to varying
interpretations. Our cost of drilling, completing and operating wells is often
uncertain before drilling commences. Overruns in budgeted expenditures are
common risks that can make a particular project uneconomical. Further, many
factors may curtail, delay or cancel drilling, including the following:

- pressure or irregularities in geological formations;

- shortages of or delays in obtaining equipment and qualified personnel;

- equipment failures or accidents;

- adverse weather conditions, such as hurricanes and tropical storms;

- reductions in oil and natural gas prices;

- title problems; and

- limitations in the market for oil and natural gas.

WE MAY INCUR SUBSTANTIAL LOSSES AND BE SUBJECT TO SUBSTANTIAL LIABILITY CLAIMS
AS A RESULT OF OUR OIL AND NATURAL GAS OPERATIONS.

Losses and liabilities arising from uninsured and underinsured events could
materially and adversely affect our business, financial condition or results of
operations. Our oil and natural gas exploration and production activities are
subject to all of the operating risks associated with drilling for and producing
oil and natural gas, including the possibility of:

- environmental hazards, such as uncontrollable flows of oil, natural gas,
brine, well fluids, toxic gas or other pollution into the environment,
including groundwater and shoreline contamination;

- abnormally pressured formations;

- mechanical difficulties, such as stuck oil field drilling and service
tools and casing collapse;

- fires and explosions;

- personal injuries and death; and

- natural disasters, especially hurricanes and tropical storms in the Gulf
of Mexico.

Offshore operations are also subject to a variety of operating risks
peculiar to the marine environment, such as capsizing, collisions and damage or
loss from hurricanes, tropical storms or other adverse weather conditions. These
conditions can cause substantial damage to facilities and interrupt production.
15

Any of these risks could adversely affect our ability to conduct operations
or result in substantial losses to our company. We maintain insurance at levels
that we believe are consistent with industry practices and our particular needs,
but we are not fully insured against all risks. We may elect not to obtain
insurance if we believe that the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks
generally are not fully insurable. If a significant accident or other event
occurs and is not fully covered by insurance, it could adversely affect our cash
flow and net income and could reduce or eliminate the funds available for
exploration, exploitation and acquisitions or result in loss of equipment and
properties.

A SUBSTANTIAL OR EXTENDED DECLINE IN OIL AND NATURAL GAS PRICES MAY ADVERSELY
AFFECT OUR BUSINESS, FINANCIAL CONDITION OR RESULTS OF OPERATIONS AND OUR
ABILITY TO MEET OUR CAPITAL EXPENDITURE REQUIREMENTS AND FINANCIAL
COMMITMENTS.

The price we receive for our oil and natural gas production heavily
influences our revenue, profitability, access to capital and future rate of
growth. Oil and natural gas are commodities and, therefore, their prices are
subject to wide fluctuations in response to relatively minor changes in supply
and demand. Historically, the markets for oil and natural gas have been
volatile. These markets will likely continue to be volatile in the future. The
prices we receive for our production, and the levels of our production, depend
on numerous factors beyond our control. These factors include:

- changes in the global supply, demand and inventories of oil;

- domestic natural gas supply, demand and inventories;

- the actions of the Organization of Petroleum Exporting Countries, or
OPEC;

- the price and quantity of foreign imports of oil;

- the price and availability of liquefied natural gas imports;

- political conditions, including embargoes, in or affecting other
oil-producing countries;

- economic and energy infrastructure disruptions caused by actual or
threatened acts of war, or terrorist activities, or national security
measures deployed to protect the United States from such actual or
threatened acts or activities;

- economic stability of major oil and natural gas companies and the
interdependence of oil and natural gas and energy trading companies;

- the level of worldwide oil and natural gas exploration and production
activity;

- weather conditions;

- technological advances affecting energy consumption; and

- the price and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our revenues on a
per unit basis, but also may reduce the amount of oil and natural gas that we
can produce economically. A substantial or extended decline in oil and natural
gas prices may materially and adversely affect our future business, financial
condition, results of operations, liquidity, ability to finance planned capital
expenditures or ability to pursue acquisitions. Further, oil prices and natural
gas prices do not necessarily move together.

RESERVE ESTIMATES DEPEND ON MANY ASSUMPTIONS THAT MAY PROVE TO BE INACCURATE.
ANY MATERIAL INACCURACIES IN THESE RESERVE ESTIMATES OR UNDERLYING ASSUMPTIONS
WILL MATERIALLY AFFECT THE QUANTITIES AND PRESENT VALUE OF OUR RESERVES.

The process of estimating oil and natural gas reserves is complex. It
requires interpretations of available technical data and many assumptions,
including assumptions relating to economic factors. Any significant

16

inaccuracies in these interpretations or assumptions could materially affect the
estimated quantities and present value of reserves shown in this Report.

In order to assist our independent petroleum engineers in the preparation
of our estimates, we must project production rates and timing of development
expenditures. We must also analyze available geological, geophysical, production
and engineering data. The extent, quality and reliability of these data can
vary. The process also requires economic assumptions about matters such as oil
and natural gas prices, drilling and operating expenses, capital expenditures,
taxes and availability of funds. Therefore, estimates of oil and natural gas
reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves most likely will vary from our estimates.

It cannot be assumed that the present value of future net revenues from our
proved reserves referred to in this Report is the current market value of our
estimated oil and natural gas reserves. In accordance with SEC requirements, we
base the estimated discounted future net cash flows from our proved reserves on
prices and costs on the date of the estimate. Actual future prices and costs may
differ materially from those used in the present-value estimate.

MARKET CONDITIONS OR OPERATIONAL IMPEDIMENTS MAY HINDER OUR ACCESS TO OIL AND
NATURAL GAS MARKETS OR DELAY OUR PRODUCTION.

Market conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas markets
or delay our production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including the demand for
and supply of oil and natural gas and the proximity of reserves to pipelines and
terminal facilities. Our ability to market our production depends in substantial
part on the availability and capacity of gathering systems, pipelines and
processing facilities owned and operated by third parties. Our failure to obtain
such services on acceptable terms could harm our business. We may be required to
shut in wells for lack of a market or because of inadequacy or unavailability of
oil or natural gas pipeline or gathering system capacity. If that were to occur,
we would be unable to realize revenue from those wells until production
arrangements were made to deliver to market.

RISKS RELATING TO ENERGY PARTNERS, LTD.

A SIGNIFICANT PART OF THE VALUE OF OUR PRODUCTION AND RESERVES IS CONCENTRATED
IN TWO PROPERTIES. BECAUSE OF THIS CONCENTRATION, ANY PRODUCTION PROBLEMS OR
INACCURACIES IN RESERVE ESTIMATES RELATED TO THESE PROPERTIES COULD IMPACT OUR
BUSINESS ADVERSELY.

During the month of December 2004, 32% of our net daily production came
from our East Bay field. If mechanical problems, storms or other events were to
curtail a substantial portion of this production, our cash flow would be
affected adversely. Also, at December 31, 2004, approximately 39% of our proved
reserves were located on this property. In addition, at December 31, 2004
approximately 34% of our proved reserves were located in our Greater Bay
Marchand area. If the actual reserves associated with these properties are less
than our estimated reserves, our business, financial condition or results of
operations could be adversely affected.

RELATIVELY SHORT PRODUCTION LIFE FOR GULF OF MEXICO REGION PROPERTIES SUBJECTS
US TO HIGHER RESERVE REPLACEMENT NEEDS.

Producing oil and natural gas reservoirs generally are characterized by
declining production rates that vary depending upon reservoir characteristics
and other factors. High production rates generally result in recovery of a
relatively higher percentage of reserves from properties during the initial few
years of production. All of our operations are in the Gulf of Mexico region.
Production from reserves in reservoirs in the Gulf of Mexico region generally
declines more rapidly than from reservoirs in many other producing regions of
the world. As of December 31, 2004, or independent petroleum engineers estimate,
on average, 69% of our total proved reserves will be produced within 5 years. As
a result, our reserve replacement needs from new

17

investments are relatively greater than those of producers who recover lower
percentages of their reserves over a similar time period, such as producers who
have a portion of their reserves outside the Gulf of Mexico in areas where the
rate of reserve production is lower. We may not be able to develop, exploit,
find or acquire additional reserves to sustain our current production levels or
to grow. There can be no assurance that we will be able to grow production at
rates we have experienced in the past. Our future oil and natural gas reserves
and production, and, therefore, our cash flow and income, are highly dependent
on our success in efficiently developing and exploiting our current reserves and
economically finding or acquiring additional recoverable reserves.

RAPID GROWTH MAY PLACE SIGNIFICANT DEMANDS ON OUR RESOURCES.

We have experienced rapid growth in our operations and expect that
expansion of our operations will continue. Our rapid growth has placed, and our
anticipated future growth will continue to place, a significant demand on our
managerial, operational and financial resources due to:

- the need to manage relationships with various strategic partners and
other third parties;

- difficulties in hiring and retaining skilled personnel necessary to
support our business;

- complexities in integrating acquired businesses and personnel;

- the need to train and manage our employee base; and

- pressures for the continued development of our financial and information
management systems.

If we have not made adequate allowances for the costs and risks associated
with these demands or if our systems, procedures or controls are not adequate to
support our operations, our business could be harmed.

PROPERTIES THAT WE BUY MAY NOT PRODUCE AS PROJECTED, AND WE MAY BE UNABLE TO
FULLY IDENTIFY LIABILITIES ASSOCIATED WITH THE PROPERTIES OR OBTAIN PROTECTION
FROM SELLERS AGAINST THEM.

Our strategy includes acquisitions. The successful acquisition of producing
properties requires assessments of many factors, which are inherently inexact
and may be inaccurate, including:

- the amount of recoverable reserves and the rates at which those reserves
will be produced;

- future oil and natural gas prices;

- estimates of operating costs;

- estimates of future development costs;

- estimates of the costs and timing of plugging and abandonment; and

- potential environmental and other liabilities.

Our assessments will not reveal all existing or potential problems, nor
will they permit us to become familiar enough with the properties to evaluate
fully their deficiencies and capabilities. In the course of our due diligence,
we may not inspect every well, platform or pipeline. We cannot necessarily
observe structural and environmental problems, such as pipeline corrosion or
groundwater contamination, when an inspection is conducted. We may not be able
to obtain contractual indemnities from the seller for liabilities that it
created. We may be required to assume the risk of the physical condition of the
properties in addition to the risk that the properties may not perform in
accordance with our expectations.

SUBSTANTIAL ACQUISITIONS, DEVELOPMENT PROGRAMS OR OTHER TRANSACTIONS COULD
REQUIRE SIGNIFICANT EXTERNAL CAPITAL AND COULD CHANGE OUR RISK AND PROPERTY
PROFILE.

In order to finance acquisitions of additional producing properties or
finance the development of any discoveries made through any expanded exploratory
program that might be undertaken, we may need to alter or increase our
capitalization substantially through the issuance of additional debt or equity
securities, the sale of production payments or other means. These changes in
capitalization may significantly affect our risk
18

profile. Additionally, significant acquisitions or other transactions can change
the character of our operations and business. The character of the new
properties may be substantially different in operating or geological
characteristics or geographic location than our existing properties.
Furthermore, we may not be able to obtain external funding for any such
transactions or to obtain additional external funding on terms acceptable to us.

THE UNAVAILABILITY OR HIGH COST OF DRILLING RIGS, EQUIPMENT, SUPPLIES,
PERSONNEL AND OILFIELD SERVICES COULD ADVERSELY AFFECT OUR ABILITY TO EXECUTE
ON A TIMELY BASIS OUR EXPLORATION AND DEVELOPMENT PLANS WITHIN OUR BUDGET.

All of our operations are in the Gulf of Mexico region. Shortages or the
high cost of drilling rigs, equipment, supplies or personnel could delay or
adversely affect our development and exploration operations, which could have a
material adverse effect on our business, financial condition or results of
operations. Periodically, as a result of increased drilling activity or a
decrease in the supply of equipment, materials and services, we have experienced
increases in associated costs, including those related to drilling rigs,
equipment, supplies and personnel and the services and products of other vendors
to the industry. Increased drilling activity in the Gulf of Mexico also
decreases the availability of offshore rigs. We cannot offer assurance that
costs will not increase again or that necessary equipment and services will be
available to us at economical prices.

PROVISIONS IN OUR ORGANIZATION DOCUMENTS AND UNDER DELAWARE LAW COULD DELAY OR
PREVENT A CHANGE IN CONTROL OF OUR COMPANY, WHICH COULD ADVERSELY AFFECT THE
PRICE OF OUR COMMON STOCK.

The existence of some provisions in our organizational documents and under
Delaware law could delay or prevent a change in control of our company, which
could adversely affect the price of our common stock. The provisions in our
certificate of incorporation and bylaws that could delay or prevent an
unsolicited change in control of our company include:

- the board of directors' ability to issue shares of preferred stock and
determine the terms of the preferred stock without approval of common
stockholders; and

- a prohibition on the right of stockholders to call meetings and a
limitation on the right of stockholders to act by written consent and to
present proposals or make nominations at stockholder meetings.

In addition, Delaware law imposes some restrictions on mergers and other
business combinations between us and any holder of 15% or more of our
outstanding common stock.

THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT US.

To a large extent, we depend on the services of our founder and chairman,
president and chief executive officer, Richard A. Bachmann, and other senior
management personnel. The loss of the services of Mr. Bachmann or other senior
management personnel could have an adverse effect on our operations. We do not
maintain any insurance against the loss of any of these individuals.

The exploration and production business is highly competitive, and our
success will depend largely on our ability to attract and retain experienced
geoscientists and other professional staff.

COMPETITION IN THE OIL AND NATURAL GAS INDUSTRY IS INTENSE, WHICH MAY
ADVERSELY AFFECT US.

We operate in a highly competitive environment for acquiring oil and
natural gas properties, marketing oil and natural gas and securing trained
personnel. Many of our competitors possess and employ financial, technical and
personnel resources substantially greater than ours, which can be particularly
important in Gulf of Mexico activities. Those companies may be able to pay more
for productive oil and natural gas properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or personnel resources permit. Our ability to
acquire additional prospects and to discover reserves in the future will depend
on our ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and natural gas
industry. We cannot make assurances that we will be
19

able to compete successfully in the future in acquiring prospective reserves,
developing reserves, marketing hydrocarbons, attracting and retaining quality
personnel and raising additional capital. If we are unable to compete
successfully in these areas in the future, our future revenues and growth may be
diminished or restricted.

SIGNIFICANT CUSTOMERS

We market substantially all of the oil and natural gas from properties we
operate and from properties others operate where our interest is significant. A
majority of oil production from the East Bay field is sold under a contract with
Shell Trading (US) Company ("Shell"). The contract has a 60 day cancellation
provision and can be cancelled by either party. In the event that the contract
is cancelled by us, Shell has the right to match any other offers we receive for
purchase of our oil production. Our oil, condensate and natural gas production
is sold to a variety of purchasers, typically at market-sensitive prices. Our
purchasers of oil and condensate include ChevronTexaco Global Trading
("ChevronTexaco") and Shell. Currently, the most significant purchaser of our
natural gas production is Louis Dreyfus Energy Services, L.P. ("Dreyfus"). We
believe that the prices for liquids and natural gas are comparable to market
prices in the areas where we have production. We also have a natural gas
processing arrangement for our production at our Bay Marchand and East Bay
fields with Dynegy Midstream Services, L.P. Of our total oil and natural gas
revenues in 2004, Shell accounted for approximately 22 percent, Dreyfus 14
percent and ChevronTexaco 13 percent.

Due to the nature of the markets for oil and natural gas, we do not believe
that the loss of any one of these customers would have a material adverse effect
on our financial condition or results of operation although a temporary
disruption in production revenues could occur.

EMPLOYEES

As of December 31, 2004, we had 151 full-time employees, including 42
geoscientists, engineers and technicians and 48 field personnel. Our employees
are not represented by any labor union. We consider relations with our employees
to be satisfactory and we have never experienced a work stoppage or strike.

ITEM 3. LEGAL PROCEEDINGS

In the ordinary course of business, we are a defendant in various legal
proceedings. We do not expect our exposure in these proceedings, individually or
in the aggregate, to have a material adverse effect on our financial position,
results of operations or liquidity.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth certain information regarding our executive
officers:

20

Richard A. Bachmann has been president and chief executive officer and
chairman of the board of directors since our incorporation in January 1998. Mr.
Bachmann began organizing our company in February 1997. From 1995 to January
1997, he served as director, president and chief operating officer of LL&E, an
independent oil and natural gas exploration company. From 1982 to 1995, Mr.
Bachmann held various positions with LL&E, including director, executive vice
president, chief financial officer and senior vice president of finance and
administration. From 1978 to 1981, Mr. Bachmann was treasurer of Itel
Corporation. Prior to 1978, Mr. Bachmann served with Exxon International, Esso
Central America, Esso InterAmerica and Standard Oil of New Jersey. He has also
been nominated to become a director of Trico Marine Services, Inc.

Suzanne V. Baer joined us in April 2000 as vice president and chief
financial officer and was promoted to executive vice president in May 2001. Ms.
Baer has 35 years of financial management, investor relations and treasury
experience in the energy industry. From July 1998 until March 2000, Ms. Baer had
been vice president and treasurer of Burlington Resources Inc. and, from October
1997 to July 1998, was vice president and assistant treasurer of Burlington
Resources. Prior to the merger of LL&E with Burlington Resources in 1997, Ms.
Baer was vice president and treasurer of LL&E since 1995. Subsequent to the year
ended December 31, 2004 Ms. Baer announced her plan to retire in April 2005. Her
successor, David R. Looney, began service in February 2005 and will become our
new chief financial officer following their transition period and his
appointment by our Board of Directors.

Phillip A. Gobe joined us in December 2004 as chief operating officer. Mr.
Gobe has over 28 years of energy industry experience and was with Nuevo Energy
Company as chief operating officer from February 2001 until its acquisition by
Plains Exploration & Production Company in May 2004. Mr. Gobe's primary
responsibilities were managing Nuevo's domestic and international exploitation
and exploration operations. Prior to his position with Nuevo, Mr. Gobe had been
the Senior Vice President of Production for Vastar Resources, Inc. since 1997.
From 1976 to 1997, Mr. Gobe worked for Atlantic Richfield Company and its
subsidiaries in positions of increasing responsibility, primarily in the Gulf of
Mexico and Alaska.

John H. Peper joined us in January 2002, following the closing of the HHOC
acquisition, as executive vice president, general counsel and corporate
secretary. Prior to joining us, Mr. Peper had been senior vice president,
general counsel and secretary of HHOC since February 1993. Mr. Peper also served
as a director of HHOC since October 1991. For more than five years prior to
joining HHOC, Mr. Peper was a partner in the law firm of Jackson Walker, L.L.P.,
where he continued to serve in an of counsel capacity through 2001.

T. Rodney Dykes joined us in April 2001 as general manager of operations
and was elected vice president of operations in July 2001. He served as our vice
president of exploitation for the period from March 2002 through July 2003 and
was elected senior vice president -- production in July 2003. Mr. Dykes has over
25 years experience in the energy industry. Immediately prior to joining us, Mr.
Dykes worked as an independent consultant. From 1994 to 1999, Mr. Dykes held
various positions with CMS Oil and Gas Company, including divisional operations
manager, vice president of operations and vice president of business
development. From 1980 to 1994, he held various technical, drilling and
production management positions with Maxus Energy. Prior to 1980, Mr. Dykes was
a petroleum engineer with Kerr McGee.

William Flores, Jr. joined us in August 2003 as senior vice
president -- drilling. Mr. Flores has over 22 years experience in the energy
industry. From 1999 to 2003, he was senior vice president of drilling for Ocean
Energy, Inc. and from 1993 to 1999 he was vice president of operations of Ocean
Energy, Inc. From 1988 to 1993, Mr. Flores was a senior drilling engineer for
CNG Producing. From 1983 to 1988, he worked as a consulting engineer at the
consulting firm of Stokes and Spiehler. Prior to 1983, Mr. Flores was a
petroleum engineer for Apache Oil Company.

21

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS

Our common stock is listed on the New York Stock Exchange under the symbol
"EPL." The following table sets forth, for the periods indicated, the range of
the high and low sales prices of our common stock as reported by the New York
Stock Exchange.

On February 25, 2005 the last reported sale price of our common stock on
the New York Stock Exchange was $25.65 per share.

As of February 25, 2005 there were approximately 100 holders of record of
our common stock.

We have not paid any cash dividends in the past on our common stock and do
not intend to pay cash dividends on our common stock in the foreseeable future.
We intend to retain earnings for the future operation and development of our
business. Any future cash dividends to holders of common stock would depend on
future earnings, capital requirements, our financial condition and other factors
determined by our board of directors.

22

ITEM 6. SELECTED FINANCIAL DATA

The following table shows selected consolidated financial data derived from
our consolidated financial statements which are set forth in Item 8 of this
Report. The data should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" in Item 7 of this
Report.

- ---------------

(1) The 2000 loss from operations includes a one time non-cash stock
compensation charge for shares released from escrow to management and
director stockholders of $38.2 million and a non-cash charge of $2.1 million
for bonus shares awarded to employees at the time of the initial public
offering. The after-tax amount of these charges totaled $39.5 million.
Although these charges reduced our net income, they increased
paid-in-capital and thus did not result in a net reduction of total
stockholders' equity. These charges were partially offset by a gain on sale
of oil and natural gas assets of $7.8 million.

(2) The 2003 net income includes a cumulative effect of change in accounting
principle resulting from the adoption of Statement 143, which increased net
income $2.3 million, net of deferred income taxes of $1.3 million.

(3) Net income (loss) available to common stockholders is computed by
subtracting preferred stock dividends and accretion of discount of $3.4
million, $3.5 million and $3.3 million from net income (loss) for the years
ended December 31, 2004, 2003 and 2002, respectively; and by subtracting
preferred stock dividends and accretion of issuance costs of $6.7 million
for the year ended December 31, 2000.

23

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

OVERVIEW

We were incorporated in January 1998 and operate in a single segment as an
independent oil and natural gas exploration and production company. Our
operations in 2004 were concentrated in the shallow to moderate depth waters of
the Gulf of Mexico Shelf. In January 2005 we extended our operations into the
Gulf Coast onshore region through an acquisition of properties in South
Louisiana.

In 2004, we achieved another year of growth and reported the best year on a
revenue and net income as well as per-share basis over our seven-year history.
Our strong cash flow provided us the flexibility to make necessary and
appropriate investments to continue our long-term growth strategy. Our long-term
strategy is to increase our oil and natural gas reserves and production while
keeping our finding and development costs and operating costs competitive with
our industry peers. We will implement this strategy through drilling exploratory
and development wells from our inventory of available prospects that we have
evaluated for geologic and mechanical risk and future reserve or resource
potential and by making acquisitions, including acquisitions in our core focus
area. Our drilling program will contain some higher risk, higher reserve
potential opportunities as well as some lower risk, lower reserve potential
opportunities, in order to achieve a balanced program of reserve and production
growth.

We use the successful efforts method of accounting for our investment in
oil and natural gas properties. Under this method, we capitalize lease
acquisition costs, costs to drill and complete exploration wells in which proven
reserves are discovered and costs to drill and complete development wells.
Seismic, geological and geophysical, and delay rental expenditures are expensed
as incurred. We conduct many of our exploration and development activities
jointly with others and, accordingly, recorded amounts for our oil and natural
gas properties reflect only our proportionate interest in such activities.

On November 1, 2000, we consummated our initial public offering of 5.75
million shares of common stock. On April 16, 2003, we completed the public
offering of approximately 4.2 million shares of our common stock priced at $9.50
per share. The equity offering also included shares offered by our then
principal stockholder, Evercore Capital Partners, L.P. and certain of its
affiliates ("Evercore"), and by Energy Income Fund, L.P. ("EIF"). After payment
of underwriting discounts and commissions, the offering generated net proceeds
to us of approximately $38.0 million. After expenses of approximately $0.5
million, the proceeds were used to repay a portion of outstanding borrowings
under our bank credit facility.

In January 2002 we acquired HHOC. In addition to other consideration paid,
former preferred stockholders of HHOC have the right to receive contingent
consideration based upon a percentage of the amount by which the before tax net
present value of proved reserves related, in general, to exploratory prospect
acreage held by HHOC as of the closing date exceeds a net present value
discounted at 30%. The contingent consideration may be paid in the Company's
common stock or cash at the Company's option (with a minimum of 20% paid in cash
for each payment) and in no event will exceed a value of $50 million. Due to the
uncertainty inherent in estimating the value of the contingent consideration,
total final consideration will not be determined until March 1, 2007. The
contingent consideration paid will be capitalized as additional purchase price.

On August 5, 2003, we issued $150 million of 8.75% Senior Notes due 2010
(the "Senior Notes") in a Rule 144A private offering (the "Debt Offering") which
allows unregistered transactions with qualified institutional and non-U.S.
purchasers. After discounts and commissions and all offering expenses, we
received $145.3 million, which was used to redeem all of our outstanding 11%
Senior Subordinated Notes due 2009 and to repay substantially all of the
borrowings outstanding under our bank credit facility. The remainder of the net
proceeds was set aside for general corporate purposes, including acquisitions.
In October 2003, we consummated an exchange offer pursuant to which we exchanged
registered Senior Notes having substantially identical terms as the Senior Notes
for the privately placed Senior Notes.

During 2003, Evercore on two occasions exercised a contractual right to
request us to register with the SEC the possible public sale of our common stock
held by it. Subsequent to each of these requests Evercore priced two public
offerings to sell shares of our common stock. These offerings completed the sale
of its
24

interest in our company. We did not sell any shares in either of these two
offerings and did not receive any proceeds from the shares offered by Evercore.

On July 16, 2004, we filed a universal shelf registration statement which
allowed us to issue an aggregate of $300 million in common stock, preferred
stock, senior debt and subordinated debt in one or more separate offerings with
the size, price and terms to be determined at the time of the sale. On November
10, 2004 we sold approximately 3.5 million shares of our common stock to the
public pursuant to this shelf registration statement, leaving us with the
ability to issue an additional $239.6 million of securities under the shelf
registration statement. Concurrent with this offering, we entered into a stock
purchase agreement with EIF in which we purchased approximately 3.5 million
shares of common stock owned by EIF at a price per share equal to the net
proceeds per share received in the offering, before expenses. We did not retain
any of the proceeds from the offering and the shares are now held as treasury
shares, at cost. We have no immediate plans to enter into any additional
transactions under this registration statement, but plan to use the proceeds of
any future offering under this registration statement for general corporate
purposes, which may include debt repayment, acquisitions, expansion and working
capital.

On August 3, 2004 we amended and extended to August 3, 2008 our bank credit
facility. Under the amendment our initial borrowing base remained $60 million.
The borrowing base was increased to $150 million at the time of our purchase of
south Louisiana properties and reserves in January 2005. The borrowing base will
remain subject to redetermination based on the proved reserves of the oil and
natural gas properties that serve as collateral for the bank credit facility.

Our revenue, profitability and future growth rate depend on a number of
factors beyond our control, such as economic, political and regulatory
developments and competition from other sources of energy. Oil and natural gas
prices historically have been volatile and may fluctuate widely in the future.
Sustained periods of low prices for oil and natural gas could materially and
adversely affect our financial position, our results of operations, the
quantities of oil and natural gas reserves that we can economically produce and
our access to capital. See "Additional Factors Affecting Business" in Items 1
and 2 for a more detailed discussion of these risks.

We currently have an extensive inventory of drillable prospects in-house,
we are generating more internally and we are being exposed to new opportunities
through relationships with industry partners. Despite our expanded budget in
2005, strong commodity prices, together with growing production volumes, should
enable us to adhere to our policy of funding our exploration and development
expenditures with internally generated cash flow. This strategy allows us to
preserve our strong balance sheet to finance acquisitions and other capital
intensive projects that might result from our exploration and development
activities. In addition to the south Louisiana property acquisition already
completed in 2005, we believe this year will provide us a number of
opportunities to acquire targeted properties, including those within our focus
area.

25

RESULTS OF OPERATIONS

The following table presents information about our oil and natural gas
operations.

REVENUES AND NET INCOME

Our oil and natural gas revenues increased to $294.5 million in 2004 from
$229.7 million in 2003. In 2004, the oil and natural gas industry experienced
record high oil prices as well as sustained high natural gas

26

prices. The increase in revenue for this period is the result of these
significantly increased natural gas and oil prices combined with increased
production resulting primarily from the commencement of production from 20 new
wells brought on production since year end 2003, 16 of which were natural gas.
These increases were partially offset by natural reservoir declines. In
addition, volumes were negatively affected by Hurricane Ivan and Tropical Storm
Matthew.

Our oil and natural gas revenues increased to $229.7 million in 2003 from
$134.1 million in 2002. The significant increase for this period is the result
of increased natural gas and oil prices and increased natural gas production due
primarily to new production from 21 wells drilled in 2002 and in the first half
of 2003. These increases were partially offset by natural reservoir declines. In
addition, 2002 volumes were negatively affected by tropical storm activity.

We recognized net income of $46.4 million in 2004 compared to net income of
$33.3 million in 2003. The increase in net income was primarily due to the
increase in oil and natural gas revenues previously discussed and partially
offset by higher operating costs, as discussed below. We recognized net income
of $33.3 million in 2003 compared to net loss of $8.8 million in 2002. The
increase in net income was primarily due to the increase in oil and natural gas
revenues previously discussed and partially offset by higher operating costs, as
discussed below. The following items had a significant impact on our net income
or loss in 2004, 2003 and 2002 and affect the comparability of the results of
operations for those years:

- In January 2003, we adopted Statement of Financial Accounting Standards
No. 143, "Accounting for Asset Retirement Obligations" ("Statement 143")
and the effect of adoption on our results of operations and financial
condition included a cumulative effect of adoption income of $2.3
million, net of deferred income taxes of $1.3 million.

- In March 2002, in connection with management's plan to reduce costs and
effectively combine the operations of HHOC with ours, we executed a
severance plan and recorded an expense of $1.2 million.

OPERATING EXPENSES

Operating expenses were impacted by the following:

- Lease operating expense increased $3.9 million to $40.6 million in 2004.
This is a result of the addition of production from new fields and $1.0
million related to the retained loss portion of repairs due to Hurricane
Ivan.

Lease operating expense increased $2.3 million to $36.7 million in 2003.
This was a result of the addition of production from new fields, whereas
the majority of our new production in the past was primarily from our
large fields with existing infrastructure and low variable cost. Despite
the increase in absolute costs, our operating costs per Boe decreased due
to the lower fixed costs required for these new fields.

- Taxes, other than on earnings increased $1.6 million to $9.3 million in
2004. This increase was due to the increase in commodity prices received
for our oil and natural gas production on state leases, primarily at East
Bay and Bay Marchand, which are subject to Louisiana severance taxes.
These taxes are expected to fluctuate from period to period depending on
our production volumes from state leases and the commodity prices
received.

Taxes, other than on earnings increased $1.1 million to $7.7 million in
2003. This increase was due to the increase in the production volumes and
prices received for our oil and natural gas production on state leases,
primarily at East Bay and Bay Marchand, which is subject to Louisiana
severance taxes.

- Exploration expenditures increased $18.5 million to $35.9 million in
2004. The expense in 2004 is primarily the result of an increase in dry
hole charges of $10.9 million to $21.0 million as a result of exploratory
wells drilled during the year which were found to be noncommercial, as
well as property impairments of $6.9 million at our East Cameron 378
field and seismic expenditures and delay rentals which increased $3.5
million to $8.0 million. Our exploration expenditures, including dry hole
charges will vary depending on the amount of our capital budget dedicated
to exploration activities and the
27

level of success we achieve in exploratory drilling activities. Although
our dry hole costs were higher in 2004, we allocated more dollars to
exploration in 2004 while maintaining a comparable success rate.

Exploration expenditures increased $6.7 million to $17.4 million in 2003.
The expense in 2003 is primarily the result of an increase in dry hole
charges to $10.1 million as a result of exploratory wells drilled during
the year which were found to be noncommercial, as well as property
impairments of $2.8 million, partially offset by a slight decrease in
seismic expenditures and delay rentals to $4.5 million. Although our dry
hole costs were higher in 2003, we allocated more dollars to exploration
in 2003 while maintaining a comparable success rate.

- Depreciation, depletion and amortization increased $10.5 million to $92.4
million in 2004. The increase was due to the increased depreciable asset
base combined with higher production and a shift in the production
contribution from our various fields. Some fields carry a higher
depreciation burden than others, therefore, changes in the location of
our production will directly impact this expense. This expense includes
$6.6 million of amortization for our asset retirement obligation for 2004
as compared to $5.2 million in 2003.

Depreciation, depletion and amortization increased $17.4 million to $81.9
million in 2003. The increase was due to the increased depreciable asset
base combined with higher production and a shift in the production
contribution from our various fields. This expense includes $5.2 million
of amortization for our asset retirement obligation for 2003 as compared
to $6.8 million in 2002.

- Other general and administrative expenses increased $1.2 million to $27.9
million in 2004. The increase was primarily due to increased consulting
costs ($1.9 million), of which $0.4 million was increased costs paid to
our internal audit service provider and external auditors to implement
the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. The
remainder included increased human resources, land and engineering
consulting costs. This was offset by decreased casualty insurance ($0.4
million) and decreased technology costs ($0.2 million).

Other general and administrative expenses increased $4.2 million to $26.7
million in 2003. The increase was primarily due to increased compensation
($5.6 million) and increased insurance ($0.6 million) offset by a 2002
litigation settlement ($2.0 million), which increased general and
administrative expenses during the prior year.

- Non-cash stock-based compensation expense of $3.1 million was recognized
in 2004, an increase of $1.8 million from 2003. This expense has
increased due to additional grants of restricted shares and performance
share awards to employees. The level of expense for these awards is also
affected by the increased stock price in 2004.

Non-cash stock-based compensation expense of $1.3 million was recognized
in 2003, an increase of $0.8 million from 2002. This expense has increased
due to additional grants of restricted shares and the granting of
performance share awards to employees.

OTHER INCOME AND EXPENSE

Interest expense increased $4.2 million to $14.4 million in 2004. The
increase was a result of interest expense on the 8.75% Senior Notes issued in
August 2003 partially offset by the interest savings from the redemption of the
11% Notes and the repayment of the bank facility in 2003.

Interest expense increased $3.2 million to $10.2 million in 2003. The
increase was a result of interest expense on the 8.75% Senior Notes issued in
August 2003 partially offset by the interest savings from the redemption of the
11% Notes and the repayment of the bank facility.

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES

The increase in revenues we experienced in 2004 increased our cash flows
from operations, which totaled $165.1 million. We intend to fund our exploration
and development expenditures from internally generated cash flows, which we
define as cash flows from operations before consideration of changes in working
capital
28

plus total exploration expenditures. Our cash on hand at December 31, 2004 was
$93.5 million, substantially all of which was used in the purchase of the south
Louisiana properties in January 2005. Our future internally generated cash flows
will depend on our ability to maintain and increase production through our
development and exploratory drilling program, as well as the prices of oil and
natural gas. We may from time to time use the availability of our bank credit
facility to balance working capital needs.

Our bank credit facility, as amended on August 3, 2004, consists of a
revolving line of credit with a group of banks available through August 3, 2008
(the "bank credit facility"). The bank credit facility had a borrowing base of
$60 million. The borrowing base was increased to $150 million at the time of our
purchase of south Louisiana properties and reserves in January 2005. The bank
credit facility is subject to redetermination based on the proved reserves of
the oil and natural gas properties that serve as collateral for the bank credit
facility as set out in the reserve report delivered to the banks each April 1
and October 1. The bank credit facility permits both prime rate based borrowings
and London interbank offered rate ("LIBOR") borrowings plus a floating spread.
The spread will float up or down based on our utilization of the bank credit
facility. The spread can range from 1.25% to 2.00% above LIBOR and 0% to 0.75%
above prime. The borrowing base under the bank credit facility is secured by
substantially all of our assets. We used our bank credit facility to fund a
portion of the purchase of the south Louisiana properties in January 2005 and
the acquisition of the additional interest in South Timbalier 26 in March 2005.
As a result at March 8, 2005, we had $70.0 million outstanding and $80.0 million
of credit capacity available under the bank credit facility. In addition, we pay
an annual fee on the unused portion of the bank credit facility ranging between
0.375% to 0.5% based on utilization. The bank credit facility contains customary
events of default and various financial covenants, which require us to: (i)
maintain a minimum current ratio of 1.0 as defined in our bank credit facility
agreement, and (ii) maintain a minimum EBITDAX to interest ratio of 3.5 times.
We were in compliance with these covenants as of December 31, 2004.

On August 5, 2003, we issued $150 million of 8.75% Senior Notes due 2010.
The Senior Notes bear interest at a rate of 8.75% per annum with interest
payable semi-annually on February 1 and August 1, beginning February 1, 2004. We
may redeem the notes at our option, in whole or in part, at any time on or after
August 1, 2007 at a price equal to 100% of the principal amount plus accrued and
unpaid interest, if any, plus a specified premium which decreases yearly from
4.375% in 2007 to 0% in 2009 and thereafter. In addition, at any time prior to
August 1, 2006, we may redeem up to a maximum of 35% of the aggregate principal
amount with the net proceeds of certain equity offerings at a price equal to
108.75% of the principal amount, plus accrued and unpaid interest. The notes are
unsecured obligations and rank equal in right of payment to all existing and
future senior debt, including the bank credit facility, and will rank senior or
equal in right of payment to all existing and future subordinated indebtedness.
The indenture relating to the Senior Notes contains certain restrictions on our
ability to incur additional debt, pay dividends on our common stock, make
investments, create liens on our assets, engage in transactions with our
affiliates, transfer or sell assets and consolidate or merge substantially all
of our assets. The Senior Notes are not subject to any sinking fund
requirements.

Upon closing on the Senior Notes on August 5, 2003, we called our $38.4
million 11% Notes due 2009 for redemption. The redemption of the Notes in
aggregate principal and accrued interest was funded with a portion of the
proceeds received from the Senior Notes and was completed in August 2003. The
Notes were issued on January 15, 2002 as part of the acquisition financing of
HHOC. In addition, $39.9 million of the proceeds from the Senior Notes were used
to re-pay substantially all of the borrowings under the bank credit facility. As
a result of the issuance of the Senior Notes, our bank credit facility borrowing
base was reduced from $100 million to $60 million requiring a non-cash charge of
$0.3 million for the write-off of the pro rata remaining balance of unamortized
issue costs.

Net cash of $176.7 million used in investing activities in 2004 primarily
included oil and natural gas property capital and exploration expenditures of
$163.0 million, lease acquisitions of $6.6 million and a deposit of $5.0 million
paid for the January 2005 purchase of south Louisiana reserves and prospects
from Castex. Exploration expenditures incurred are excluded from operating cash
flows and included in investing activities. During 2004, we completed 31
drilling projects and 21 recompletion/workover projects, 41 of which were

29

successful. During 2003, we completed 23 drilling projects and 33
recompletion/workover projects, 46 of which were successful.

Our 2005 capital exploration and development budget is focused on
exploration, exploitation and development activities on our proved properties
combined with moderate and higher risk exploratory activities on undeveloped
leases and does not include acquisitions, including the acquisitions of
properties and reserves to date in 2005. We currently intend to allocate
approximately 55% of our budget on low risk development and exploitation
activities, approximately 30% to moderate risk exploration opportunities and
approximately 15% to higher risk, higher potential exploration opportunities.
Our exploration and development budget for 2005 is currently $240 million,
inclusive of expected expenditures on the properties acquired in January 2005.
The level of our budget is based on many factors, including results of our
drilling program, oil and natural gas prices, industry conditions, participation
by other working interest owners and the costs of drilling rigs and other
oilfield goods and services. Should actual conditions differ materially from
expectations, some projects may be accelerated or deferred and, consequently,
may increase or decrease total 2005 capital expenditures.

We have experienced and expect to continue to experience substantial
working capital requirements, primarily due to our active exploration and
development program. We believe that internally generated cash flows will be
sufficient to meet our capital requirements for at least the next twelve mont